Methods of forming a chemical casing

ABSTRACT

Methods of forming chemical casings include drilling a well bore with a drilling fluid having a pH in the range of from about 6 to 10 and comprising water, a water soluble or water dispersible polymer which is capable of being cross-linked by a thermoset resin and causing the resin to be hard and tough when cured, a particulate curable solid thermoset resin, a water soluble or dispersible thermoset resin, and a delayed dispersible acid-catalyst for curing the solid thermoset resin and the water soluble thermoset resin, whereby the drilling fluid forms a filter cake on the walls of the wellbore that cures into a hard and tough cross-linked chemical casing thereon.

CROSS-REFERENCE TO RELATED APPLICATION

This is a Divisional of application Ser. No. 10/170,400 filed on Jun.13, 2002 now U.S. Pat. No. 6,702,044.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to methods of forming a chemical casing ina well bore penetrating a weak unconsolidated zone or formation.

2. Description of the Prior Art

Rotary drilling methods are commonly utilized in the drilling of oil andgas wells. That is, the well bore which extends from the surface intoone or more subterranean oil and/or gas producing formations is drilledby a rotary drilling rig on the surface which rotates a drill bitattached to a string of drill pipe. The drill bit includes rotatablecutting surfaces so that when the drill bit is rotated by the drillstring against subterranean strata under pressure a bore hole isproduced.

A drilling fluid is circulated downwardly through the drill string,through the drill bit and upwardly in the annulus between the walls ofthe well bore and the drill string. The drilling fluid functions tomaintain hydrostatic pressure on formations penetrated by the well boreand to remove cuttings from the well bore. As the drilling fluid iscirculated, a filter cake of solids from the drilling fluid forms on thewalls of the well bore. The filter cake build-up is a result of initialfluid loss into permeable formations and zones penetrated by the wellbore. The presence of the filter cake reduces additional fluid loss asthe well is drilled.

In addition to removing cuttings from the well bore and forming filtercake on the well bore, the drilling fluid cools and lubricates the drillbit and exerts a hydrostatic pressure against the well bore walls toprevent blow-outs, i.e., to prevent pressurized formation fluids fromflowing into the well bore when formations containing the pressurizedfluids are penetrated. The hydrostatic pressure created by the drillingfluid in the well bore may fracture low mechanical strength formationspenetrated by the well bore which allows drilling fluid to be lost intothe formations. When this occurs, the drilling of the well bore must bestopped and remedial steps taken to seal the fractures which are timeconsuming and expensive.

In order to insure that fracturing of low mechanical strength formationspenetrated by the well bore and other similar problems do not occur, ithas heretofore been the practice to intermittently seal the well bore bycementing pipe referred to in the art as casing or liners in the wellbore. The points in the well bore during its drilling at which thedrilling is stopped and casing or liners are installed in the well boreare commonly referred to as “casing points”. Casing or a liner is placedin the well bore above each casing point and a sealing composition suchas a hydraulic cement composition is pumped into the annular spacebetween the walls of the well bore and the exterior surface of thecasing or liner disposed therein. The hydraulic cement composition ispermitted to set in the annulus thereby forming an annular sheath ofhardened substantially impermeable cement therein. The cement sheathphysically supports and positions the pipe in the well bore and bondsthe pipe to the walls of the well bore whereby the undesirable migrationof fluids between zones or formations penetrated by the well bore isprevented. This technique of cementing pipe in the well bore as thedrilling progresses has a number of disadvantages including the time andexpense incurred in placing and sealing the pipe as well as thereduction in the well diameter after each casing point. That is, thewell diameter must be reduced below each casing point so that a smallercasing can be lowered through the previously placed casing and sealed inthe well bore.

Another problem that occurs in the drilling and completion of well boresis that when the well bore is drilled into and through unconsolidatedweak zones or formations formed of clays, shales, sand stone and thelike, unconsolidated clay, shale and sand slough off the sides of thewell bore which enlarges the well bore and often causes the drill bitand drill pipe to become stuck whereby drilling must be stopped andremedial steps taken.

Thus, there are needs for improved methods of drilling well boreswhereby unconsolidated weak zones or formations are consolidated and themechanical strength of the well bore is increased during drillingwithout the need to stop drilling for prolonged periods of time.

SUMMARY OF THE INVENTION

By the present invention, methods of consolidating unconsolidated weakzones or formations during drilling are provided. Also, methods offorming a hard and tough chemical casing in a well bore during drillingto increase the mechanical strength of the well bore are provided. Thechemical casing formed while drilling also prevents undesirablemigration of fluid between zones or formations penetrated by the wellbore, generally referred to as “zonal isolation.” The methods ofconsolidating unconsolidated weak zones or formations during drilling orforming a hard and tough chemical casing during drilling can be carriedout separately or simultaneously.

A method of this invention for consolidating unconsolidated weak zonesor formations formed of clays, shales, sand stone and the like whiledrilling a well bore penetrating the zones or formations to preventsloughing is as follows. A well bore is drilled with a drilling fluidhaving a pH in the range of from about 6 to about 10 and comprised ofwater, a polymeric cationic catalyst capable of accepting and donatingprotons which is adsorbed on the unconsolidated clays, shales, sandstone and the like, a water soluble or dispersible polymer which iscross-linkable by a thermoset resin and causes the resin to be hard andtough when cured and a water soluble or dispersible thermoset resinwhich cross-links the polymer, is catalyzed and cured by the catalystand consolidates the weak zones or formations so that sloughing isprevented.

Another method of this invention for consolidating unconsolidated weakzones or formations formed of clays, shales, sand stone and the likewhile drilling a well bore penetrating the zones or formations toprevent sloughing is comprised of the following steps. A well bore isdrilled with a drilling fluid having a pH in the range of from about 6to about 10 and comprised of water and a polymeric cationic catalystcapable of accepting and donating protons which is adsorbed on theunconsolidated clays, shales, sand stone and the like. Thereafter, thewell bore is contacted with a treating fluid having a pH in the range offrom about 6 to about 10 and comprised of water, a water soluble ordispersible polymer which is cross-linkable by a thermoset resin andcauses the resin to be hard and tough when cured and a water soluble ordispersible thermoset resin which cross-links the polymer, is catalyzedand cured by the catalyst and consolidates the weak zones or formationsso that sloughing is prevented.

A method of this invention for forming a chemical casing in a well boreto improve the mechanical strength thereof and/or prevent undesirablemigration of fluids between zones or formations while drilling the wellbore is as follows. A well bore is drilled with a drilling fluid havinga pH in the range of from about 6 to about 10 and comprised of water, awater soluble or water dispersible polymer which is cross-linkable bythermoset resins and causes the resins to be hard and tough when cured,a particulate curable solid thermoset resin, a water soluble thermosetresin, and a delayed dispersible acid catalyst for curing the solidthermoset resin and the water soluble thermoset resin, the drillingfluid forming a filter cake on the walls of the well bore that curesinto a hard and tough cross-linked chemical casing thereon.

A method of this invention for consolidating unconsolidated weak zonesor formations formed of clays, shales, sand stone and the like toprevent sloughing and forming a chemical casing in a well borepenetrating the weak zones or formations to improve the mechanicalstrength of the well bore and/or prevent undesirable migration of fluidsbetween zones or formations while drilling the well bore is as follows.A well bore is drilled with a drilling fluid having a pH in the range offrom about 6 to about 10 and comprised of water, a polymeric cationiccatalyst capable of accepting and donating protons which is adsorbed onthe unconsolidated clays, shales, sand stone and the like, a watersoluble or dispersible polymer which is cross-linkable by a thermosetresin and causes the resin to be hard and tough when cured, aparticulate curable solid thermoset resin, a water soluble thermosetresin and a delayed dispersible acid catalyst for curing the thermosetresins, the drilling fluid forming a filter cake on the walls of thewell bore that cures and consolidates the unconsolidated weak zones andformations penetrated by the well bore so that sloughing is preventedand forms a hard and tough cross-linked chemical casing on the walls ofthe well bore which prevents the undesirable migration of fluids betweenzones or formations.

Another method of this invention for consolidating unconsolidated weakzones or formations formed of clays, shales, sand stone and the like toprevent sloughing and forming a chemical casing in a well borepenetrating the weak zones or formations to improve the mechanicalstrength of the well bore while drilling the well bore is comprised ofthe following steps. A well bore is drilled with a drilling fluid havinga pH in the range of from about 6 to about 10 and comprised of water, apolymeric cationic catalyst capable of accepting and donating protonswhich is adsorbed on the unconsolidated clays, shales, sand stone andthe like, a particulate curable solid thermoset resin and a delayed acidcatalyst for curing the solid thermoset resin, the drilling fluidforming a filter cake on the walls of the well bore that cures andconsolidates the unconsolidated weak zones and formations penetrated bythe well bore so that sloughing is prevented. Thereafter, the well boreis contacted with a treating fluid comprised of water, a water solubleor dispersible polymer which is cross-linkable by a thermoset resin andcauses the resin to be hard and tough when cured and a water soluble ordispersible thermoset resin, the treating fluid components depositing onthe filter cake formed by the drilling fluid and the thermoset resincuring into a hard and tough cross-linked chemical casing on the wallsof the well bore.

The objects, features and advantages of the invention will be readilyapparent to those skilled in the art upon a reading of the descriptionof preferred embodiments which follows.

DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention provides methods of consolidating unconsolidatedweak zones or formations formed of clays, shales, sand stone and thelike while drilling a well bore penetrating the zones or formations toprevent sloughing, methods of forming a hard and tough cross-linkedchemical casing in a well bore while drilling the well bore whichincreases the mechanical strength of the well bore and provides zonalisolation and methods of both consolidating unconsolidated weak zones orformations penetrated by a well bore and forming a hard and toughcross-linked chemical casing in the well bore while drilling the wellbore.

Unstable materials such as clays, shales, sand stone and the like makeup a high percentage of the formations in which wells are drilled, and amajority of well bore problems are a result of the instability of suchmaterials, particularly shale instability. Shales are sedimentary rocksthat contain a variety of clays. Shales containing montmorillonite,often referred to as smectite clays, swell and disperse when contactedby water. Shales which swell upon contacting water are often referred toas heaving or sloughing shales. Such shales upon contact with aqueousdrilling fluids swell and fracture rendering the well bore wallunstable. In such cases, the well bore wall sloughs into the well bore.Sloughing of shale and other similar unstable materials into the wellbore can cause the drill string to become stuck and can enlarge the wellbore resulting in large subterranean cavities. Additionally, whensloughing occurs while the drill bit is being changed at the surface,the well bore fills up and must be cleared before drilling can proceed.Furthermore, the heaving unstable material suspended in the drillingfluid increases its solid content, and as a result, the viscosity of thedrilling fluid increases to the point where the drilling fluid must bechemically treated to reduce its viscosity or it must be dilutedfollowed by the addition of weighting material to maintain its mudweight. The instability of clays, shales, sand stone and the like isalso caused by hydraulic pressure differential leading to fluidtransport and by pressure changes near the well bore as the drillingfluid compresses pore fluid and diffuses a pressure front into theformation. The chemicals and other materials used in accordance with thepresent invention prevent swelling and dispersion of unstable materials,reduce pressure transmission from the well bore fluids and preventdrilling fluid penetration into the unstable materials by building animpenetrable lining at the unstable material/well bore interface.

Consolidating unconsolidated weak zones or formations formed of clays,shales, sand stone and the like while drilling a well bore preventssloughing of the clays, shales, sand stone and the like into the wellbore and prevents the need for implementing time consuming and costlyremedial steps. The formation of a hard and tough chemical casing in awell bore while the well bore is being drilled increases the mechanicalstrength of the well bore whereby hydrostatic pressure exerted on thewell bore by the drilling fluid does not cause fractures or the like tooccur in the well bore. Such fractures cause drilling fluid to be lostand also require stoppage of the drilling operation and costly remedialsteps to be taken. Another significant advantage of increasing themechanical strength of the well bore by forming a hard and toughchemical casing thereon is the reduction or elimination of casing pointsat which casing or liners are cemented in the well bore which reduces oreliminates the overall time and cost of cementing the well. Anadditional advantage is that the well bore has a larger diameter in theproduction zone due to fewer casing points which increases productivity.

A method of the present invention for consolidating unconsolidated weakzones or formations formed of clays, shales, sand stone and the likewhile drilling a well bore penetrating the zones or formations toprevent sloughing comprises drilling the well bore with a drilling fluidhaving a pH in the range of from about 6 to about 10, preferably about8. The drilling fluid is comprised of water, a polymeric cationiccatalyst capable of accepting and donating protons which is adsorbed onthe unconsolidated clays, shales, sand stone and the like, a watersoluble or dispersible polymer which is cross-linkable by a thermosetresin and causes the resin to be hard and tough when cured and a watersoluble or dispersible thermoset resin which cross-links the polymer, iscatalyzed and cured by the catalyst and consolidates the weak zones orformations so that sloughing is prevented.

The water utilized to form the drilling fluid can be fresh water,unsaturated salt solutions or saturated salt solutions, including brineand seawater. Generally, water from any source can be utilized so longas it doesn't adversely react with components of the drilling fluid.

Examples of polymeric cationic catalysts capable of accepting anddonating protons which are adsorbed on clays, shales, sand stone and thelike include, but are not limited to, polyethyleneimine,poly(dimethylaminoethylmethacrylate) andpoly(dimethylaminopropylmethacrylate). Of these, polyethyleneimine ispreferred. The polymeric cationic catalyst is generally included in thedrilling fluid in an amount in the range of from about 1% to about 15%by weight of water in the drilling fluid, more preferably in an amountin the range of from about 2% to about 10% by weight of the water andmost preferably in an amount of about 6%.

The water soluble or dispersible polymers which are cross-linked by thethermoset resins utilized in accordance with this invention are polymerscontaining one or more of hydroxyl, amide, carboxyl and epoxy functionalgroups. Examples of such polymers include, but are not limited to,acrylic latexes, polyvinylalcohol, polyvinylbutyral, polyesters,polyalkylacrylic acids, polyurethanes, acrylamide polymers, proteins,polyols and polysaccharides such as chitosan, hydroxyethylcellulose,carboxymethylhydroxyethylcellulose, water soluble starches, guar gum,xanthan gum, welan gum, carragenan gum and arabic gum. Of these,polysaccharides are preferred. The water soluble or dispersible polymerwhich is cross-linked by thermoset resins is generally included in thedrilling fluid in an amount in the range of from about 0.5% to about 20%by weight of water in the drilling fluid, more preferably in an amountin the range of from about 1% to about 10% by weight of the water andmost preferably in an amount of about 3%.

The water soluble or dispersible thermoset resins (including particulatesolid thermoset resins having a particle size in the range of from about50 to about 1000) utilized in accordance with this invention areselected from melamine-formaldehyde type resins, i.e., amino resins madefrom melamine and formaldehyde, urea-formaldehyde type resins, i.e.,amino resins made from urea and formaldehyde and phenol-formaldehydetype resins, i.e., synthetic thermoset resins made from phenol andformaldehyde. More preferably, the thermoset resins utilized areselected from alkyl ethers of melamine-formaldehyde resins and alkylethers of urea-formaldehyde resins. Of these, alkyl ethers ofmelamine-formaldehyde resins are preferred. An alkyl ether ofmelamine-formaldehyde resin which is particularly suitable iscommercially available under the tradename “ASTRO MEL CR1™” from BordenChemical of Springfield, Oreg., USA. The water soluble or dispersiblethermoset resin utilized in the above described method is generallypresent in the drilling fluid in an amount in the range of from about 5%to about 80% by weight of water in the drilling fluid, more preferablyin an amount in the range of from about 20% to about 70% by weight ofwater and most preferably in an amount of about 50%.

The thermoset resins described above, when catalyzed by heat, catalystsor other means, form substantially infusible or insoluble materialswhich do not soften on reheating. When cross-linked and cured, thethermoset polymers are strong, hard and tough.

As will be understood by those skilled in the art, the drilling fluidsof this invention can include other conventional components such asweighting materials, viscosifiers, dispersants and fluid loss controlagents.

Another method of this invention for consolidating unconsolidated weakzones or formations formed of clays, shales, sand stone and the likewhile drilling a well bore penetrating the zones or formations toprevent sloughing is comprised of the following steps. The well bore isdrilled with a drilling fluid having a pH in the range of from about 6to about 10, preferably 8, and is comprised of water and a polymericcationic catalyst capable of accepting and donating protons which isadsorbed on the unconsolidated clays, shales, sand stone and the like.Thereafter, the well bore is contacted with a treating fluid having a pHin the range of from about 6 to about 10, preferably 8, and comprised ofwater, a water soluble or dispersible polymer which is cross-linkable bya thermoset resin and causes the resin to be hard and tough when curedand a water soluble or dispersible thermoset resin which cross-links thepolymer, is catalyzed and cured by the catalyst and consolidates theweak zones or formations so that sloughing is prevented.

The components of the drilling fluid and treating fluid of the abovedescribed method, i.e., the water, the polymeric cationic catalyst, thewater soluble or dispersible polymer which is cross-linkable by athermoset resin and the water soluble or dispersible thermoset resin arethe same as those previously described.

The polymeric cationic catalyst is present in the drilling fluid in ageneral amount in the range of from about 1% to about 15% by weight ofwater in the drilling fluid, more preferably in an amount in the rangeof from about 2% to about 10% by weight of the water and most preferablyin an amount of about 6%.

The water soluble or dispersible polymer which is cross-linked by athermoset resin is present in the treating fluid in a general amount inthe range of from about 0.5% to about 20% by weight of water in thetreating fluid, more preferably in an amount in the range of from about1% to about 10% of the water and most preferably in an amount of about3%. The water soluble or dispersible thermoset resin is present in thetreating fluid in a general amount in the range of from about 5% toabout 80% by weight of the water and most preferably in an amount ofabout 50%.

The drilling fluid as well as the treating fluid can also include otheradditives which are well known to those skilled in the art such asweighting materials, viscosifiers, dispersants and fluid loss controlagents.

The first method described above which utilizes a single fluid fordrilling the well bore and simultaneously consolidating weak zones orformations is utilized at locations where it is known thatunconsolidated weak zones and formations will be encountered. The secondmethod described above which utilizes both a drilling fluid and atreating fluid is used in drilling applications where it is unknown ifunconsolidated weak zones or formations will be encountered. In thesecond method, if unconsolidated weak zones or formations are notencountered, the treating fluid step is not required and the time andexpense required for performing the treating fluid step will be saved.

A method of this invention for forming a chemical casing in a well borefor improving the mechanical strength thereof and provide zonalisolation to prevent fluid flow between zones or formations whiledrilling the well bore is as follows. The well bore is drilled with adrilling fluid having a pH in the range of from about 6 to about 10,preferably 8. The drilling fluid is comprised of water, a water solubleor water dispersible polymer which is cross-linkable by a thermosetresin and causes the resin to be hard and tough when cured, aparticulate curable solid thermoset resin, a water soluble thermosetresin, and a delayed dispersible acid catalyst for curing the solidthermoset resin and the water soluble thermoset resin. The drillingfluid components form a filter cake on the walls of the well bore thatcures into a hard and tough cross-linked chemical casing thereon.

The water soluble or dispersible polymer which is cross-linked by athermoset resin is selected from the group consisting of polymerscontaining one or more of hydroxyl, amide, carboxyl and epoxy functionalgroups. Examples of such polymers include, but are not limited to,acrylic latexes, polyvinylalcohol, polyvinylbutyral, polyesters,polyalkylacrylic acids, polyurethanes, acrylamide polymers, proteins,polyols and polysaccharides such as chitosan, hydroxyethylcellulose,carboxymethylhydroxyethylcellulose, water soluble starches, guar gum,xanthan gum, welan gum, carragenan gum and arabic gum. The polymer isincluded in the drilling fluid in an amount in the range of from about0.5% to about 20% by weight of water in the drilling fluid, morepreferably in an amount in the range of from about 1% to about 10% byweight of water and most preferably in an amount of about 3%.

As mentioned above, the particulate curable solid thermoset resin has aparticle size in the range of from about 50 to about 1000 microns and isselected from particulate solid melamine-formaldehyde type resins,urea-formaldehyde type resins or phenol-formaldehyde type resins, andmore preferably from particulate solid alkyl esters ofmelamine-formaldehyde resins and particulate solid alkyl esters ofurea-formaldehyde resins. Of these, the particulate solid alkyl estersof melamine-formaldehyde resins are preferred. The particulate curablesolid thermoset resin used is included in the drilling fluid in thegeneral amount in the range of from about 5% to about 50% by weight ofwater in the drilling fluid, more preferably in an amount in the rangeof from about 10% to about 30% by weight of water and most preferably inan amount of about 15%.

The water soluble thermoset resin is selected from water solublemelamine-formaldehyde type resins, urea-formaldehyde type resins orphenol-formaldehyde type resins, and more preferably from water solublealkyl ethers of melamine-formaldehyde resins and water soluble alkylethers of urea-formaldehyde resins. Of these, water soluble alkyl ethersof melamine-formaldehyde resins are preferred. The water solublethermoset resin used is included in the drilling fluid in an amount inthe range of from about 5% to about 80% by weight of water in thedrilling fluid, more preferably in an amount in the range of from about20% to about 70% by weight of water and most preferably in an amount ofabout 50%.

The acid in the delayed dispersible acid catalyst is an organic orinorganic acid selected from the group consisting of p-toluene sulfonicacid, dinonylnaphthalene sulfonic acid, dodecyl benzene sulfonic acid,oxalic acid, maleic acid, hexamic acid, a copolymer of phthalic andacrylic acid, trifluoromethane sulfonic acid, phosphoric acid, sulfuricacid, hydrochloric acid, sulfamic acid and ammonium salts that produceacids when dissolved in water. Of these, ammonium chloride is preferred.The acid in the delayed acid utilized is included in the drilling fluidin a general amount in the range of from about 0.5% to about 8% byweight of thermoset resin in the drilling fluid, more preferably in anamount in the range of from about 1% to about 6% by weight of resin andmost preferably in an amount of about 4%.

The acid utilized can be delayed using various techniques known to thoseskilled in the art. A preferred technique for controlling the release ofthe acid catalyst utilized in the present invention is to cause the acidto be absorbed into a particulate porous solid material whereby the acidis encapsulated. When the encapsulated acid is combined with thedrilling fluid, it is slowly released into the drilling fluid. While avariety of porous solid materials can be utilized, particularly suitablesuch materials are inorganic porous solid materials which remain dry andfree flowing after absorbing a liquid chemical additive therein.Examples of such porous solid materials include, but are not limited to,metal oxides, e.g., silica and alumina; metal salts ofalumina-silicates, e.g., zeolites, clays and hydrotalcites; and others.Of the various particulate porous solid materials that can be used,particulate porous silica is preferred with precipitated silica beingthe most preferred.

The delayed release of a liquid chemical additive absorbed inparticulate porous precipitated silica is by osmosis whereby theencapsulated liquid chemical diffuses through the porous solid materialas a result of it being at a higher concentration within the porousmaterial than its concentration in the liquid fluid outside the porousmaterial. In order to further delay the release of a liquid chemicaladditive, the porous precipitated silica can be coated with a slowlysoluble coating. Examples of suitable such slowly soluble materialswhich can be used include, but are not limited to, EDPM rubber,polyvinyldichloride (PVDC), nylon, waxes, polyurethanes, cross-linkedpartially hydrolyzed acrylics and the like. A more detailed descriptionof the encapsulating techniques described above is set forth in U.S.Pat. No. 6,209,646 issued on Apr. 3, 2001 to Reddy et al., thedisclosure of which is incorporated herein by reference thereto.

In order to strengthen the chemical casing formed in the well bore, oneor more insoluble reinforcing materials can be included in the drillingfluid. The reinforcing materials become a part of the filter cakedeposited on the walls of the well bore that cures into a hard and toughcasing thereon. The presence of the reinforcing materials in the strong,hard and tough chemical casing provides additional strength to thechemical casing. The insoluble reinforcing materials which can beutilized include, but are not limited to, carbon fibers, glass fibers,mineral fibers, cellulose fibers, silica, zeolite, alumina, calciumsulfate hemihydrate, acrylic latexes, polyol-polyesters and polyvinylbutyral. Of these, fibrous materials or calcium sulfate hemihydrate arepreferred. When used, the reinforcing material is included in thedrilling fluid in an amount in the range of from about 2% to about 25%by weight of water in the drilling fluid, more preferably in an amountin the range of from about 5% to about 20% by weight of water and mostpreferably in an amount of about 10%.

As mentioned above, the drilling fluid can include other conventionaldrilling fluid additives which are known to those skilled in the art.

A combined method of this invention for both consolidatingunconsolidated weak zones or formations formed of clays, shales, sandstone and the like to prevent sloughing and for forming a chemicalcasing in a well bore penetrating the weak zones or formations toimprove the mechanical strength thereof and/or to provide zonalisolation while drilling the well bore is as follows. A well bore isdrilled with a drilling fluid having a pH in the range of from about 6to about 10, preferably 8. The drilling fluid is comprised of water, apolymeric cationic catalyst capable of accepting and donating protonswhich is adsorbed on the unconsolidated clays, shales, sand stone andthe like, a water soluble or dispersible polymer which is cross-linkedby a thermoset resin and causes the resin to be hard and tough whencured, a particulate curable solid thermoset resin, a water solublethermoset resin and a delayed dispersible acid catalyst for curing thethermoset resins, the drilling fluid forming a filter cake on the wallsof the well bore that cures and consolidates the unconsolidated weakzones and formations penetrated by the well bore so that sloughing isprevented and forms a hard and tough cross-linked chemical casing on thewalls of the well bore.

The polymeric cationic catalyst in the drilling fluid is selected fromthe group consisting of polyethyleneimine,poly(dimethylaminoethylmethacrylate) andpoly(dimethylaminopropylmethacrylate). Of these, polyethyleneimine ispreferred. The polymeric cationic catalyst is included in the drillingfluid in an amount in the range of from about 1% to about 15% by weightof water in the drilling fluid, more preferably in an amount in therange of from about 2% to about 10% by weight of water and mostpreferably in an amount of about 6%.

The water soluble or dispersible polymer which is cross-linked by athermoset resin utilized in the drilling fluid is selected from polymerscontaining one or more of hydroxyl, amide, carboxyl and epoxy functionalgroups. Examples of such polymers include, but are not limited to,acrylic latexes, polyvinylalcohol, polyvinylbutyral, polyesters,polyalkylacrylic acids, polyurethanes, acrylamide polymers, proteins,polyols and polysaccharides such as chitosan, hydroxyethylcellulose,carboxymethylhydroxyethylcellulose, water soluble starches, guar gum,xanthan gum, welan gum, carragenan gum and arabic gum. Of these,polysaccharides are preferred. The water soluble or dispersible polymerwhich is cross-linked by a thermoset resin is generally present in thedrilling fluid in an amount in the range of from about 0.5% to about 20%by weight of water in the drilling fluid, more preferably in an amountin the range of from about 1% to about 10% by weight of water and mostpreferably in an amount of about 3%.

The particulate curable solid thermoset resin which preferably has aparticle size in the range of from about 50 to about 1000 microns isselected from particulate solid melamine-formaldehyde type resins,urea-formaldehyde type resins or phenol-formaldehyde resins, and morepreferably from particulate solid alkyl ethers of melamine-formaldehyderesins and particulate solid alkyl ethers of urea-formaldehyde typeresins. Of these, particulate solid alkyl ethers ofmelamine-formaldehyde resins are preferred. The particulate curablesolid thermoset resin is generally included in the drilling fluid in anamount in the range of from about 5% to about 50% by weight of water inthe drilling fluid, more preferably in an amount in the range of fromabout 10% to about 30% by weight of water and most preferably in anamount of about 15%.

The water soluble thermoset resin is selected from the group consistingof water soluble alkyl ethers of melamine-formaldehyde resins, watersoluble alkyl ethers of urea-formaldehyde resins and water solublephenol-formaldehyde type resins. Of these, a water soluble alkyl etherof melamine-formaldehyde resin is preferred. The water soluble thermosetresin is included in the drilling fluid in an amount in the range offrom about 5% to about 80% by weight of water in the drilling fluid,more preferably in an amount in the range of from about 20% to about 70%by weight of water and most preferably in an amount of about 50%.

The acid in the delayed acid catalyst in the drilling fluid is anorganic or inorganic acid selected from the group consisting ofp-toluene sulfonic acid, dinonylnaphthalene sulfonic acid, dodecylbenzene sulfonic acid, oxalic acid, maleic acid, hexamic acid, acopolymer of phthalic and acrylic acid, trifluoromethane sulfonic acid,phosphoric acid, sulfuric acid, hydrochloric acid, sulfamic acid andammonium salts that produce acids when dissolved in water. Of these,ammonium chloride acid is preferred. The acid in the delayed acidcatalyst utilized is generally present in the drilling fluid in anamount in the range of from about 0.5% to about 8% by weight of thethermoset resin in the drilling fluid, more preferably in an amount inthe range of from about 1% to about 6% by weight of resin and mostpreferably in an amount of about 4%.

The drilling fluid can optionally include an insoluble chemical casingreinforcing material selected from the group consisting of carbonfibers, glass fibers, mineral fibers, cellulose fibers, silica, zeolite,alumina, calcium sulfate hemihydrate, acrylic latexes, polyol-polyestersand polyvinyl butyral. Of these, fibrous materials or calcium sulfatehemihydrate are preferred. When used, the insoluble reinforcing materialis generally present in the drilling fluid in an amount in the range offrom about 2% to about 25% by weight of water in the drilling fluid,more preferably in an amount in the range of from about 5% to about 20%by weight of water and most preferably in an amount of about 10%.

As mentioned above, the drilling fluid can also include conventionaladditives known to those skilled in the art.

Another method of consolidating unconsolidated weak zones or formationsformed of clays, shales, sand stone and the like to prevent sloughingand forming a chemical casing in a well bore penetrating the weak zonesor formations to improve the mechanical strength of the well bore and/orto provide zonal isolation while drilling the well bore is comprised ofthe steps of: (a) drilling the well bore with a drilling fluid having apH in the range of from about 6 to about 10, preferably 8, and comprisedof water, a polymeric cationic catalyst capable of accepting anddonating protons which is adsorbed on the unconsolidated clays, shales,sand stone and the like, a particulate curable solid thermoset resin anda delayed acid catalyst for curing the solid resin, the drilling fluidforming a filter cake on the walls of the well bore that cures andconsolidates the unconsolidated weak zones and formations penetrated bythe well bore so that sloughing is prevented; and (b) contacting thewell bore with a treating fluid comprised of water, a water soluble ordispersible polymer which is cross-linkable by a thermoset resin andcausing the resin to be hard and tough when cured and a water soluble ordispersible thermoset resin, the treating fluid components depositing onthe filter cake formed in step (a) and the thermoset resins curing intoa hard and tough cross-linked chemical casing on the walls of the wellbore.

The components in the drilling fluid and the treating fluid are the sameas the components described above in connection with the precedingmethod.

The polymeric cationic catalyst is generally present in the drillingfluid in an amount in the range of from about 2% to about 25% by weightof water in the drilling fluid, more preferably in an amount in therange of from about 5% to about 20% by weight of water and mostpreferably in an amount of about 10%.

The particulate curable solid thermoset resin is generally present inthe drilling fluid in an amount in the range of from about 5% to about50% by weight of water in the drilling fluid, more preferably in anamount in the range of from about 10% to about 30% by weight of waterand most preferably in an amount of about 15%.

The acid in the delayed acid catalyst is generally present in thedrilling fluid in an amount in the range of from about 0.5% to about 8%by weight of the thermoset resin in the drilling fluid, more preferablyin an amount in the range of from about 1% to about 6% by weight ofwater and most preferably in an amount of about 4%.

The water soluble or dispersible polymer which is cross-linkable by athermoset resin is generally present in the treating fluid in an amountin the range of from about 0.5% to about 20% by weight of water in thetreating fluid, more preferably in an amount in the range of from about1% to about 10% by weight of water and most preferably in an amount ofabout 3%.

The water soluble or dispersible thermoset resin is generally present inthe treating fluid in an amount in the range of from about 5% to about80% by weight of water in the drilling fluid, more preferably in anamount in the range of from about 20% to about 70% by weight of waterand most preferably in an amount of about 50%.

The drilling fluid can optionally include a reinforcing material tostrengthen the chemical casing as described above in connection with thepreceding method. When used, the reinforcing material is generallyincluded in the drilling fluid in an amount in the range of from about5% to about 50%, more preferably in an amount in the range of from about10% to about 30% by weight of water and most preferably in an amount ofabout 15%.

As mentioned, the drilling fluid can also include conventional additivesknown to those skilled in the art.

A preferred method of consolidating unconsolidated weak zones orformations formed of clays, shales, sand stone and the like whiledrilling a well bore penetrating the zones or formations to preventsloughing is comprised of drilling the well bore with a drilling fluidhaving a pH of about 8 and comprised of water, a cationicpolyethyleneimine catalyst which is adsorbed on the unconsolidatedclays, shales, sand stone and the like present in the drilling fluid inan amount in the range of from about 2% to about 10% by weight of waterin the drilling fluid, a polysaccharide polymer which is capable ofbeing cross-linked by a thermoset resin and causing the resin to be hardand tough when cured present in an amount in the range of from about 1%to about 10% by weight of water in the drilling fluid and an alkyl etherof a melamine-formaldehyde thermoset resin which cross-links thepolymer, is catalyzed and cured by the catalyst and consolidates theweak zones or formations so that sloughing is prevented present in thedrilling fluid in an amount in the range of from about 20% to about 70%by weight of water in the drilling fluid.

Another preferred method of consolidating unconsolidated weak zones orformations formed of clays, shales, sand stone and the like whiledrilling a well bore penetrating the zones or formations to preventsloughing comprises the steps of: (a) drilling the well bore with adrilling fluid having a pH of about 8 and comprised of water, a cationicpolyethyleneimine catalyst which is adsorbed on the unconsolidatedclays, shales, sand stone and the like present in the drilling fluid inan amount in the range of from about 2% to about 10% by weight of thedrilling fluid; and then (b) contacting the well bore with a treatingfluid having a pH of about 8 comprised of water, a polysaccharidepolymer which is capable of being cross-linked by a thermoset resin andcausing the resin to be hard and tough when cured present in an amountin the range of from about 1% to about 10% by weight of water in thetreating fluid and an alkyl ether of a melamine-formaldehyde thermosetresin which cross-links the polymer, is catalyzed and cured by thecatalyst and consolidates the weak zones or formations so that sloughingis prevented present in an amount in the range of from about 20% toabout 70% by weight of water in the treating fluid.

A preferred method of this invention for forming a chemical casing in awell bore to improve the mechanical strength thereof and provide zonalisolation while drilling the well bore is comprised of drilling the wellbore with a drilling fluid having a pH of about 8 and comprised ofwater, a water soluble or water dispersible polymer which is capable ofbeing cross-linked by a thermoset resin and causing the resin to be hardand tough when cured present in the drilling fluid in an amount in therange of from about 1% to about 10% by weight of water in the drillingfluid, a particulate curable solid alkyl ether of amelamine-formaldehyde thermoset resin present in the drilling fluid inan amount in the range of from about 10% to about 30% by weight of waterin the drilling fluid, a water soluble alkyl ether of amelamine-formaldehyde thermoset resin present in the drilling fluid inan amount in the range of from about 20% to about 70% by weight of waterin the drilling fluid, and a dispersible delayed ammonium chloride acidcatalyst for curing the solid thermoset resin and the water solublethermoset resin present in the drilling fluid in an amount in the rangeof from about 1% to about 6% by weight of thermoset resin in thedrilling fluid, the drilling fluid forming a filter cake on the walls ofthe well bore that cures into a hard and tough cross-linked chemicalcasing thereon.

A preferred method of consolidating unconsolidated weak zones orformations formed of clays, shales, sand stone and the like to preventsloughing and forming a chemical casing in a well bore penetrating theweak zones or formations to improve the mechanical strength thereofand/or to provide zonal isolation while drilling the well bore iscomprised of drilling the well bore with a drilling fluid having a pH ofabout 8 and comprised of water, a cationic polyethyleneimine catalystwhich is adsorbed on the unconsolidated clays, shales, sand stone andthe like present in an amount in the range of from about 2% to about 10%by weight of water in the drilling fluid, a water soluble or dispersiblepolysaccharide polymer which is cross-linkable by a thermoset resin andcauses the resin to be hard and tough when cured present in the drillingfluid in an amount in the range of from about 1% to about 10% by weightof water in the drilling fluid, a particulate curable solid alkyl etherof melamine-formaldehyde thermoset resin present in an amount in therange of from about 10% to about 30% by weight of water in the drillingfluid, a water soluble alkyl ether of melamine-formaldehyde thermosetresin present in an amount in the range of from about 20% to about 70%by weight of water in the drilling fluid and a dispersible delayedammonium chloride acid catalyst for curing the thermoset resins presentin the drilling fluid in an amount in the range of from about 1% toabout 6% by weight of thermoset resin in the drilling fluid, thedrilling fluid forming a filter cake on the walls of the well bore thatcures and consolidates the unconsolidated weak zones and formationspenetrated by the well bore so that sloughing is prevented and forms ahard and tough cross-linked chemical casing on the walls of the wellbore.

Another preferred method of consolidating unconsolidated weak zones orformations formed of clays, shales, sand stone and the like to preventsloughing and forming a chemical casing in a well bore penetrating theweak zones or formations to improve the mechanical strength of the wellbore and/or to provide zonal isolation while drilling the well bore iscomprised of the steps of: (a) drilling the well bore with a drillingfluid having a pH of about 8 and comprised of water, a cationicpolyethyleneimine catalyst which is adsorbed on the unconsolidatedclays, shales, sand stone and the like present in an amount in the rangeof from about 2% to about 10% by weight of water in the drilling fluid,a particulate curable solid alkyl ether of melamine-formaldehydethermoset resin present in an amount in the range of from about 10% toabout 30% by weight of water in the drilling fluid and a delayedammonium chloride acid catalyst for curing the solid resin present inthe drilling fluid in an amount in the range of from about 1% to about6% by weight of thermoset resin in the drilling fluid, the drillingfluid forming a filter cake on the walls of the well bore that cures andconsolidates the unconsolidated weak zones and formations penetrated bythe well bore so that sloughing is prevented; and (b) contacting thewell bore with a treating fluid comprised of water, a water soluble ordispersible polysaccharide polymer which is capable of beingcross-linked by a thermoset resin and causing the resin to be hard andtough when cured present in the treating fluid in an amount in the rangeof from about 1% to about 10% by weight of water in the treating fluid,a water soluble or dispersible alkyl ether of melamine-formaldehydethermoset resin present in the treating fluid in an amount in the rangeof from about 20% to about 70% by weight of water in the treating fluid,the treating fluid components depositing on the filter cake formed instep (a) and the thermoset resins curing into a hard and toughcross-linked chemical casing on the walls of the well bore.

In order to further illustrate the methods of this invention, thefollowing examples are given.

EXAMPLE 1

The application of catalyzed polyethyleneimine and melamine-formaldehyderesin on various mineral surfaces typically encountered during drillingsuch as clays, shales, sand stone and the like, was studied in thelaboratory. It was found that strongly adsorbed catalysts or activatorcomponents on the mineral surfaces of a formation catalyze the curing ofthe resin upon contact, consolidate the formation and form a chemicalcasing on the well bore surface.

Bentonite was chosen as a representative swelling clay, and kaolin as arepresentative non-swelling clay. Silica flour was chosen as a model fora sand stone formation. Ground Pierre shale was used as a typical shalemodel. A typical procedure for adsorption measurements using bentoniteas the mineral is given below.

In a round bottom flask, 10 grams of bentonite were added to 90 grams ofan aqueous solution containing 10% polyethyleneimine (PEI) with stirringat room temperature. The pH of the PEI solution was adjusted whennecessary with hydrochloric acid prior to mixing with bentonite.Aliquots of the suspension were taken periodically and centrifuged. Thesolids in the aliquots were isolated and dried at 100° C. for 3-4 hours.The amount of adsorbed material was measured by Thermal GravimetricAnalysis (TGA). The results are presented as Experiment #1 in Table 1.In subsequent experiments, variations to the above procedure were made,and the results are presented in Table 1.

TABLE 1 % % % % Experiment Polymer Salt (KCl) Adsorbed Adsorbed AdsorbedAdsorbed # Adsorbent Polymer Conc., % Conc., % pH in 1 hr. in 3 hrs. in5 hrs. in 24 hrs. 1 Bentonite PEI 10 — 10 18.08 18.5 18.1 18.2 2Bentonite PEI 10 — 9 12.2 — 16.4 16.6 3 Bentonite PEI 5 — 9 12 — 10.815.6 4 Bentonite PEI 1 — 9 7.3 — 9 9.6 5 Bentonite PEI 5 — 8 14.1 — — —6 Bentonite PEI 10 2 10.5 15 15 15 16 7 Bentonite PEI 10 7 10.5 13.313.6 13.6 13.3 8 Kaolin PEI 10 — 10.5 6 — — 9.6 9 Shale PEI 10 — 9 5.2 —— 6 10 Bentonite Resin¹ 30 — — 22 Note 2 Note 2 Note 2 11 BentoniteResin¹ 10 — — 9.8 Note 2 Note 2 Note 2 12 Bentonite gum³ + PEI 0.3% gum³in — 9.3 15.1 — 13.8 16.3 5% PEI solution 13 Silica flour PEI 1 — 9.30.43 — 1.92 — 14 Silica flour PEI 5 — 9.3 7.3 — 10.7 —¹hexamethylolmelamine partially prepolymerized and available from BordenChemical of Columbus, Ohio under the trade name “CASCO MEL MF 600 ™”.²The mixture was pasty. The solids could not be separated from theaqueous phase. ³xanthan gum.

From Table I it can be seen that PEI solutions at 10% concentration withbentonite at pH 10 reached a maximum adsorption of about 18% within onehour and remained constant over 24 hour period. In the presence of KCl,the maximum adsorbed amount decreased to about 15% at 2% KCl, and toabout 13% at 7% KCl.

A decrease of pH appears to decrease the amount of PEI adsorbed. Thisseems to indicate that oxyanionic sites on the bentonite surfaces arebeing protonated which will decrease ionic type of association andincrease weaker H-bonded associations.

Decreasing the concentration of PEI to 5% or 1% increased the time tomaximum adsorption as expected. However, the plateau adsorption levelremained in the 17-18% range. At 1% PEI, all the PEI in solution wasadsorbed onto the bentonite surface (100% theoretical). Based uponcalculations, it is predicted that there will be 100% PEI adsorptionfrom solutions with concentrations up to 2.3% to attain the maximumadsorption levels of 17-18% on bentonite.

Various adsorbents were tested for their adsorption capabilities forPEI. Bentonite adsorbs the most (˜18%), followed by Kaolin (˜10%),silica (11%) and shale (6%). It should be noted that the surface areasfor different adsorbents were not held constant.

Experiments with melamine-formaldehyde solutions at their native pHvalues reached one hour adsorption levels 22% from a 30% solution, and10% from a 10% solution. Long term adsorptions (24 hr.) measurementswere not possible because of the difficulties encountered incentrifuging the samples.

The presence of xanthan gum in the solution, even though in smallamounts seemed to accelerate the rate of PEI adsorption thusfacilitating attainment of plateau adsorption faster.

EXAMPLE 2

A drilling fluid was prepared by dissolving in a blender various amountsof xanthan gum (available from Baroid Drilling Fluids under the tradename “BARAZAN® D PLUS”) in 350 ml of deionized water and adjusting thepH to 9.3 with sodium hydroxide. The resulting solutions had yieldpoints of 1.75, 1.65, 1.1 and 1 pounds per 100 square feet.

A small block of Pierre shale stored in a sealed environment was crushedand the material collected on a U.S. Standard Sieve Series No. 12 meshscreen after passing through No. 6 mesh sieve. The above describeddrilling fluid containing the test sample dissolved in 350 grams ofdeionized water was rolled for one hour at 150° F. Into the hot fluid,30 grams of sized shale was added and rolled at 150° F. for 16 hours.The mixture was filtered through a 14 mesh screen, the retained solidswashed with tap water, dried under vacuum at 80° C. for 3 hours andweighed. The % ratio of lost weight to original weight is defined as the% shale erosion.

The results for different test materials are presented in Table 2.

TABLE 2 Experiment # #1 #2 #3 #4 #5 #6 #7 #8 #9 #10 #11 #12 #13 #14Drilling Fluid, ppb¹ 0 1.75 1.1 — — 1 1 1.65 1 — 1.1 — — — PEI, ppb¹ — —— 10 1 5 5 3 — — — — — — Resin², wt % — — — — — — — — — 30 10 — — — Poly(DMAEMA)³, wt % — — — — — — — — — — — 1 — — Poly (DMAEMA/NVP)⁴, wt % — —— — — — — — — — — — 1 — pH 9.3 9.4 9.3 9.3 9.3 9.3 8.0 9.3 9.2 9.3 9.28.0 8.0 9.3 Yield point, lb/100 ft² 0 20 10.3 — — 10.9 11.9 11.4 0.9 1.68.5 2.0 3.0 1.4 % Erosion 81 29 26 1.9 18 5.2 4.6 9.2 31 1.7 10 4 3 100¹pounds per barrel of xanthan gum in deionized water²hexamethylolmelamine partially prepolymerized and available from BordenChemical of Columbus, Ohio under the trade name “CASCO MEL MF 600 ™”.³Poly(dimethylaminoethylmethacrylate)⁴Poly(dimethylaminoethylmethacrylate-co-N-vinylpyrrolidone)

Deionized water containing xanthan gum with the pH adjusted to 9.3showed an erosion of 81%, whereas solutions containing 1.75 and 1.1 ppbshowed erosion in the 29% and 26% range, suggesting that xanthan polymeris a mild shale erosion inhibitor. Surprisingly, polyethyleneimine (PEI)showed excellent shale erosion inhibition. The pH of PEI solution is inthe highly alkaline range (˜10.5), and even at this high pH, there isapproximately 4% protonated nitrogens, whereas at a pH of 8 there is 25%protonation. Shale erosion tests with PEI (at 3-5% polymerconcentration) in the presence of xanthan gum showed erosion values inthe range of 5-10%. At 10% PEI concentration without xanthan gum, theerosion value was about 2%. Other polymers containing pendant aminogroups, for example poly(dimethylaminoethylmethacrylate) or a copolymerof dimethylaminoethylmethacrylate and N-vinylpyrrolidone, also providedexcellent shale erosion inhibitions especially at pH values near 8.0. AtpH values near 9.3 the erosion was substantial suggesting the importanceof the protonated form of these polymers in inhibiting shale erosion.

EXAMPLE 3

The ability of the compositions of the present invention to reducepressure transmission from the well bore fluids and prevent drillingfluid penetration into the shale by forming an impenetrable film at theshale/well bore interface is shown by means of pore pressuretransmission tests designed to measure fluid pressure transmissionacross a shale sample. The tests are described as follows.

The Shale sample plugs were cored perpendicular to bedding from a largewell preserved Pierre II shale cylindrical block. An inert mineralspirit was used as the coring fluid. The plugs were kept immersed in themineral spirit until testing. The plugs (nominal diameter of 25 mm) werecut into required lengths (approximately 10 mm) with a diamond-platedsaw. The flatness of the end surfaces and perpendicularity ofcircumferential surfaces to the end surfaces were checked.

The test apparatus utilized was equipped with a test solution cylinderfor each test solution, high pressure gas cylinders to provide upstream(to simulate pressure due to well bore drilling fluid) pressure and downstream (to simulate pressure due to formation fluid) pressure. Theconfining pressure was applied with a Haskell pump. The test was startedby bleeding the top (downstream) and bottom (upstream) platens withsimulated pore fluid (12% NaCl solution). The shale sample was placedbetween the platens, and the assembly was jacketed in a 1.0 mm thickmembrane. O-Rings were mounted over the jacket on the platens. Theassembly was mounted in the test cell, and a confining pressure of 20MPa was applied with water. A back pressure (upstream) of 10 MPa wasapplied and checked for flow across the upstream platen. When thedownstream pressure had stabilized at 10 MPa (pressure change <50kPa/hour, i.e., the sample was consolidated), the upstream pressure wasincreased to 15 MPa. When the downstream pressure increased byapproximately 2 MPa, the upstream pressure was decreased to 10 MPa.After the down stream pressure stabilized at 10 MPa, the sample wasreconsolidated. Then the pore fluid at the upstream end was displacedwith the test solution at 15 MPa. When the down stream pressure wasstabilized, the test solution was displaced at the upstream end with alower activity solution (saturated ammonium chloride solution). The testwas terminated when a maximum decrease in the downstream pressure wasobserved.

In order to simulate a two stage exposure of the formation to thecomponents of the present invention, the shale sample was initiallyexposed for 3 hours to a test fluid containing 3% PEI, the pH of whichwas adjusted to 8.0 with hydrochloric acid. At the end of 3 hours, thePEI solution was flushed with the simulated pore fluid at the samepressure (15 MPa), followed by a 70% aqueous melamine-formaldehyde resin(available from Borden Chemicals of Columbus, Ohio under the trade name“ASTRO MEL CR1™”) solution. The core was exposed to the resin solutionfor 3 hours, at the end of which the resin solution was flushedsequentially with simulated pore fluid followed by saturated ammoniumchloride solution. After 24 hours, the ammonium chloride solution wasreplaced with simulated pore fluid followed by a 3% PEI solutioncontaining 12% NaCl. The PEI/brine solution was allowed to stay incontact with the core until the downstream pressure stabilized. All thetesting was performed at room temperature.

Based on the downstream pressure change during the pressure transmissionchange, it was concluded that the downstream pressure increase duringthe test solution pressure transmission stage was significantly lowerthan that of the pore pressure transmission stage. In addition, thefinal downstream pressure at the end of the test solution pressuretransmission stage was significantly lower than that of the pore fluidpressure transmission change. The results strongly suggest that thereaction between PEI and the resin in the presence of ammonium chlorideon the shale surface/pores resulted in the formation of an impermeablebarrier which significantly reduced the rate of pressure transmissioninto the shale.

When the above experiment was repeated by leaving out the resinsolution, the downstream pressure during, as well as at the end, of thetest solution pressure transmission stage, as well as at the end of thepore pressure transmission stage, was identical to the upstream pressuresuggesting that the reaction product between the resin and PEI in thepresence of ammonium chloride was responsible for preventing the porefluid pressure transmission in the first experiment.

EXAMPLE 4

In this example, experiments were designed to demonstrate theeffectiveness of the compositions of the present invention inconsolidating loose sand encountered while drilling through immature andyoung sand stone formations under geopressurized conditions. For examplewhen geopressure is encountered above the depth at which the surfacecasing would be normally set or before the conventional blowoutpreventer (BOP) stack and riser are installed, the operator has twooptions: 1) drill into the geopressure without the conventionalpressure-containment system, or 2) set surface casing shallower thannormal. Either option introduces problems to the drilling operation. Ifthe incompetent sand stone formation could be consolidated such that thehigh permeability of the formation was blocked to prevent the flow offormation fluids into the well bore, and at the same time increase themechanical integrity and strength of the formation, the drillingoperation could continue uninterrupted.

A method of evaluating the sand consolidation ability of resincompositions is as follows. A blend of sand was prepared by mixing 94parts Oklahoma #1 sand of about 70-170 mesh and 6 parts silica flour(particle size smaller than about 200 mesh), and the dry blend was mixedwith 0.3 ml of API brine. This blend (100 grams) was packed into aTEFLON® polymer lined test chamber (2.38 cm I.D) or a Hassler Sleevetest chamber (2.38 cm I.D) with a pad of Oklahoma #1 sand on the bottomand a sand pad of 20-40 mesh on top of the sand pack column. A 110 gramsolution of 4.7% PEI in water with pH adjusted to 8.25 with hydrochloricacid was mixed with 45 grams of melamine-formaldehyde resin (“ASTRO MELCR1™” resin from Borden Chemical) and the resulting solution was passedthrough the dry sand pack core at room temperature under a pressure of20 psi. The sand pack assembly was separated from the rest of the setup, and kept in an oven maintained at 180° F. for 24 hours. The sandpack assembly was cooled to room temperature and the core was removed bypushing it out of the TEFLON® Sleeve. If the core when gently pressedbetween fingers did not crumble, it was determined that the core wasconsolidated due to the cured resin composition. The same procedure wasfollowed for Experiment numbers 3-8 with the changes to the compositionmentioned in Table 3. For experiment #2, a 5% PEI solution was passedthrough the dry column first followed by a 30% solution ofmelamine-formaldehyde resin in water. The heat treatment of the sandpack assembly was the same as described above. For Experiment #8, a 3%PEI solution was passed through the column first followed by a 50%melamine solution.

Consolidated sand pack cores from Experiments #7 and #8 were submittedfor mechanical property evaluation using a Load Frame.

TABLE 3 Xanthan Exper- gum, Resin, wt % PEI, % by Sand Pack CompressiveYoung's iment wt % in total wt of total Catalyst Catalyst PHConsolidation Strength of Modulus, Poisson's # in water compositioncomposition Type Amount, % (solution) (Yes/No) Sand Pack, psi psi Ratio1 None 29 4.7 HCl to adjust pH 8.25 Yes Not tested Not tested Not tested 2² None 29 Two stage HCl Adsorbed 8.25 for PEI Yes Not tested Nottested Not tested treat (5% PEI PEI.HCl salt sol.; Resin solution first)sol. pH as is 3 None 29 4.7 None None 10.8 No — — — 4 None 50 None NH₄Cl3 6.9 Yes Not tested — — 5 None 50 3 HCl to adjust pH 8.25 Yes Nottested Not tested Not tested 6 0.18 50 1.5 HCl to adjust pH 8.25 Yes Nottested Not tested Not tested 7 0.16 50 1.5 PTSA¹ to adjust pH 8.02 Yes3640 (average) 0.3880e+6 0.176  8² 0.16 50 Two stage HCl Enough to 8.02Yes 2300 (average) 0.4430e+6 0.224 treatment adjust pH (3% PEI sol.first) ¹para-toluenesulfonic acid, ²The sand pack composition waschanged to 93% Oklahoma #1 sand, 6% silica flour and 1% bentonite

The results presented in Table 3 show that the resin compositions of thepresent invention can consolidate the loose sand and provide mechanicalstrength to the consolidated sand. The resin composition comprising theresin and the adsorbing catalyst can be present together in the drillingfluid, or the sand consolidating process can be carried in two stages,the first stage involving only the catalyst in the drilling fluid andthe second stage involving the resin in a treating fluid.

EXAMPLE 5

The formation consolidating capability, and the permeability reducingability of the resin compositions of the present invention aredemonstrated by using the general experimental set up described inExample 3 with the modifications that included replacement of TEFLON®polymer liner with a rubber Hassler sleeve and the sand pack being aBrown sand stone core.

The Brown sand stone core was conditioned with 4% potassium chloridesolution and the initial permeability of the sand stone was measured. Atreatment solution was prepared by dissolving 3.14 grams of xanthan gumin 925 grams of water to which 75 grams of a 40% solution of PEI inwater were added. 500 grams of the solution was mixed with 500 grams ofmelamine-formaldehyde resin and the pH of the mixture was adjusted to8.0 with hydrochloric acid. A flow apparatus was fitted with a dry coreand flushed with a 3% PEI solution at pH 8.0 against a back pressure of100 psi. This was followed by the resin solution prepared as describedabove at 150 psi against a back pressure of 100 psi. After passing about3-4 pore volumes of the resin solution the experiment was stopped, thecore assembly was separated and cured at 180° F. for 24 hours. The setup was reassembled and the permeability of the treated core to 4%potassium chloride solution was measured. The apparatus wasdisassembled, the core was taken out and submitted for mechanicalproperty measurement. Another core was treated with an identical resinsolution with the exception that p-toluenesulfonic acid was used toadjust the pH to 8.0. The results are shown in Table 4.

TABLE 4 Resin Initial Permeability CS¹ of CS¹ of Young's Young's PoissonPoisson Treatment Permeability Reduction, % Control Treated Modulus,Modulus, Ratio, Ratio, Experiment # Composition in Darcies aftertreatment Core, psi Core, psi Control, psi Treated, psi Control Treated1 Note 2 3 >99.7 3000 5180 1.54e+6 3.08e+6 0.277 0.278 2 Note 3 3 >99.7Same as 5110 Same as 2.90 Same as 0.321 above above above ¹Compressivestrength ²50:50 mixture of melamine-formaldehyde resin (“ASTRO MELCR1 ™”) and an aqueous solution containing 3% PEI and 0.314% xanthan gumat pH 8.0 adjusted with hydrochloric acid. ³Same as the composition inNote #2 except that p-toluenesulfonic acid is used to adjust pH.

The results in Table 4 clearly show the resin composition not onlyblocks the permeability of the treated zones of the formation but alsostrengthens the formation by increasing the compressive strengths andYoung's Modulus of the rock. The results clearly show that the inflow offormation fluids into a well bore can be prevented resulting in acomplete zonal isolation conventionally achieved by casing the wellfollowed by cementing behind the casing. The consolidated rock showedstrengths similar to those for a cement column behind a casing.

EXAMPLE 6

The flow of formation fluids into a well bore during drilling istraditionally avoided by using drilling fluids which can exert a highenough hydrostatic pressure to hold back the formation fluids withoutfracturing the formation. As drilling is performed at increased depths,the density of the drilling fluids must be increased to compensate forincreased formation pore pressures at such depths. The increased muddensity would fracture the formations in the shallow zones of the wellif they are not cased prior to increasing drilling fluid density. Thenumber of casings required could be decreased if the previously drilledzones were strengthened while drilling. The pressure exerted by thedrilling fluid on the well bore walls depends on the height of thedrilling fluid column as well as the density of the fluid. Experimentswere designed in this example to simulate a well bore containing a fluidcolumn and its ability to withstand increased fluid pressure after resintreatment. The experiments were designed to demonstrate the effects ofonly the formation consolidation, the formation consolidation incombination with a chemical casing on the well bore wall and only thechemical casing on the well bore wall.

General Procedure and Experimental Set Up

A well bore model was prepared by drilling a 1¾″ (diameter)×3½″ (length)cylindrical core from a block of a Brown sand stone or of a Berea sandstone. A hole of ¾″ diameter was drilled in the center of the core. Thecylindrical was dried in an oven overnight at 200° F., cooled to roomtemperature and surface ground on top and bottom prior to use.

The experimental set up consisted of the core chamber made from a 2″stainless steel tubing collar modified by welding a flat plate on thebottom of the collar. A ¼″ nipple was then fitted and welded into a holein the center of the flat plate. The protruding portion of the nipplealso served to centralize the core by extending into the hole of thecylindrical core. A compression ¼″ fitting was then used for entranceinto the cell. The top of the chamber employed a modified 2″ hexagonalplug drilled for a ¼″ pipe fitting which was fitted with a plug. An exitport was added to the top side portion of the chamber to allow for fluidthat has been passed through the core to exit from the chamber. A ¼″steel tube connected the exit port to a back pressure regulator. Anitrogen-capped fluid chamber was connected to the core chamber from thebottom via ¼″ steel tubing.

The set up was assembled by placing a rubber gasket with a hole in thecenter on the inside bottom of the core chamber. The core was placed ontop of the gasket. Another rubber gasket with a hole in the center wasplaced on top of the core. The hexagonal lid was fitted tightly on thecore chamber. The core chamber was connected to the resin reservoir fromthe bottom with the tubing provided with a shut off valve. The exit portwas connected to the back pressure regulator with a metal tubingprovided with a shut off valve. A treating fluid was then placed in thereservoir; pressurized with 70 psi nitrogen and allowed to enter thebottom of the core chamber, to be forced up through the bottom of thecore, into the bore hole and then to exit through the top of the corechamber against a back pressure of 50 psi. Generally, when the treatingfluid was solids-free, at least 5-10 pore volumes of the treating fluidwas collected before either switching to a second fluid or terminatingthe experiment. In the case of multiple stage treatments, after thefirst fluid was passed through the core, the reservoir and the tubingleading up to the core chamber was isolated from the core chamber,cleaned and charged with the second fluid, and the operation continuedas described. In the case of a Berea core, a 4% KCl solution was passedthrough the core to stabilize the clay prior to flowing the testsolution. When the treating fluids contained solids for the purpose ofbuilding a curable filter cake or “chemical casing”, the flow wascontinued either for one hour or until the flow completely stopped. Allthe core flow experiments were performed at room temperature. After theexperiments, the set up was disassembled, the core was taken out,wrapped in an aluminum foil and rolled in an oven at 160° F. for 24hours. The core was cooled to room temperature and submitted for burststrength evaluation.

The burst strength evaluation of the treated core was performed using anMKS Loading Frame. The cylinder was mounted with an overburden pressureof 400 psi under unconfined conditions on the platform of the equipmentwith rubber gaskets each containing holes in the center on top andbottom of the core. Either mineral oil or xanthan solution was used topressurize the sample from inside. The fluid pressure at which the corefractured was taken as the burst pressure of the core.

Burst Strengths for Control Cores

The permeabilities of Brown sand stone and Berea cores were plugged bytreatment of the cores with a mixture of sodium silicate solution (38%in water, N Grade or Grade 40) sold as Injectrol A by Halliburton and asodium acid pyrophosphate solution sold as MF-1 by Halliburton. It isbelieved that the silicate gels formed from this mixture will plug thecore permeability without strengthening the core. The treatment mixturewas prepared by adding a solution of 36 grams of MF-1 in 500 ml water toa solution of 175 ml of Injectrol A in 325 ml water. After treating thecore, the core was left at room temperature for 24 hours, and subjectedto burst strength tests.

Burst strengths of 160 and 0 psi were obtained with Brown sand stonecores using oil and water as the pressurizing fluids respectively. Aburst strength of 230 psi was obtained for Berea core under the sameconditions using water as the pressurizing fluid.

Formation Consolidation

Generally, these studies were done in a two-stage process, the firststage involved passing 3% PEI (polyethyleneimine) solution adjusted topH 8.2, through the core followed by an aqueous solution containing 50%resin and 0.55% xanthan gum by weight of the total solution. Generallythe pH of the PEI solution was adjusted with HCl, and when specified,with p-toluenesulfonic acid (ptsa). Two typical procedures are describedbelow.

Procedure A (One-Stage Treatment): A 3% aqueous solution ofpolyethyleneimine (PEI) was prepared by dissolving 37.50 grams of a 40%active solution in 462.5 grams of deionized water or a xanthan polymersolution. The xanthan solution was prepared by adding 1.6 grams xanthangum to 500 grams deionized water followed by rolling the solution in arolling oven at 150° F. for 18 hours. The pH of the solution wasadjusted with hydrochloric acid or, when specified, withpara-toluenesulfonic acid (ptsa). Into this solution was dissolved 500grams of melamine-formaldehyde liquid resin or, when specified otherresins to prepare a 50% resin solution. The resulting solution was usedin treating the core as described in the General Procedure.

Procedure B (Two-Stage Treatment): In this procedure the core was firsttreated with the 3% PEI solution prepared as described above. In afollow-up stage, a xanthan solution, prepared as described above,containing the resin in the specified concentration was used to treatthe core.

The results from this study are presented in Table 5.

TABLE 5 Fluid For Burst Core Burst Strength, Experiment # Type¹ FluidComposition pH Procedure Strength psi 1 BSS 3% PEI in 0.32% xanthansolution (Stage 1); 50% 8.2² B Oil 335 resin in 0.32% xanthan solution(Stage 2) 2 BSS Same as #1 without xanthan in both the stages 8.2² B Oil0 3 BSS Same as #1 8.2³ B Oil 350 4 BSS Same as #1 8.2³ B Water 160 5BSS Same as #2 8.2³ B Water 0 6 BSS Same as #1⁴ 8.2³ B Water 250 7 BSSSame as #1 except resin concentration was increased to 70% 8.2³ B Water520 8 BSS Same as #7 except that 0.2% Silquest⁵ 8.2³ B Water 560 9 BSSSame as #1 except no xanthan in Stage 2 7.5³ B Oil 390 10 BSS Same as #17.8³ B Oil 450 11 Berea Same as #1 8.25³ B Oil 1070 12 Berea Same as #18.25³ B Water 625 13 BSS Same as #1 except a different resin⁶ was used8.2³ B Oil 240 14 BSS Same as #1 except a different resin⁷ was used 8.2³B Oil 360 15 BSS 3% PEI in 0.32% xanthan solution + Resin in water 1:1wt ratio 8.2³ A Oil 530 ¹BSS - Brown sand stone ²Para-toluenesulfonicacid was used to adjust pH (PTSA) ³Hydrochloric acid was used to adjustpH ⁴Cured at 190° F. for 24 hours⁵N-beta-(aminoethyl)-gamma-aminopropyltrimethoxysilane available fromOsi Specialties Division of Witco Corp., Greenwich, Connecticut ⁶“ASTROMel 400 ™” available from Borden Chemical. This melamine-formaldehyderesin contained less free methylol groups and higher levels of methoxymethyl groups than in “ASTRO MEL CR1 ™” also from Borden Chemical.⁷“ASTRO MEL NW 3A ™” obtained from Borden Chemical. Thismelamine-formaldehyde resin contained less free imino groups than in“ASTRO MEL CR1 ™” , but more free imino groups than in “ASTRO MEL 400 ™”

The results in Table 5 indicate that the compositions of the presentinvention increase the burst strength of the formation such that it canwithstand increased drilling fluid pressure. The importance of thepolymer for improving the strength of the formation is evident fromExperiments 1 and 2 which show that a polysaccharide, such as xanthan,in combination with the resin increases the burst strength. The resultsalso show that increasing the resin concentration, higher curingtemperatures, lower pH values increase the formation strength. Theresults also show that all the components of the invention can be addedto the drilling fluid or they can be used in a staged process. Lowerpermeability formations, for example Berea sand stone, provide higherburst strengths compared to the higher permeability formations, forexample Brown sand stone.

Formation Consolidation with Concurrent Chemical Casing on Well Bore

As mentioned earlier, this process typically involved either a one ortwo-stage process. In the first stage, a 3% PEI solution in deionizedwater was pumped into the core. In the case of Berea cores, a 4% KClsolution was passed through the core prior to the PEI solution. Thesecond stage treatment included a xanthan solution containing dissolvedmelamine-formaldehyde resin (50-70%), as well as suspended resinparticles (15% by weight of total solution). Two types of solidmaterials made from melamine-formaldehyde resins with different particlesizes were tested. Two solid urea-formaldehyde resins with differentparticle sizes were also tested. To facilitate the curing of the solidresin particles, either encapsulated or non-encapsulated ammoniumchloride in different amounts was added. Approximately, 2-4 mm thickfilter cake was formed on the core surface in these experiments.

Procedure C (Two-Stage Treatment): In the first stage the highpermeability core was treated with 3% PEI solution adjusted for pH. Inthe second stage, a 50% resin dissolved in a xanthan solution (1.1pounds per barrel) and containing 15% solid melamine-formaldehyde resin,AC Molding Chemical “M2125™” or “GM2125™”, by weight of the solution wasused to treat the core. The rest of the procedure is the same asdescribed above in the general procedure. The effect of the inclusion ofencapsulated and non-encapsulated ammonium chloride was tested fordifferent formulations. In all cases, a filter cake of 1-4 mm thick wasformed.

Procedure D (Modified Two-Stage Treatment): In the first stage, thetreatment consisted of core treatment with a suspension of 15% (by totalweight of the treatment mixture) solid resin in a xanthan solution (1.1pounds per barrel) containing 3% PEI with the pH adjusted to specifiedlevel). The second stage treatment consisted of a solution of solubleresin (Borden Chemical “ASTRO MEL CR1™”) at 70% withN-beta-(aminoethyl)-gamma-aminopropyltrimethoxysilane, available underthe trade name “SILQUEST A1120™” from OSi Specialties, a Division ofWitco Corporation, Greenwich, Conn. In all cases, a filter cake of 1-4mm thick was formed.

TABLE 6 NH₄Cl, % pH Active Fluid For Burst Experiment Core (acid Amountby wt. Burst Strength, # Type Treatment Composition used) of Total ResinProcedure Strength psi 1 BSS Stage 1: 0.3% PEI in water 8.2 0.7 C Oil410 Stage 2: 30% “ASTRO MEL CR1 ™” in 0.32% xanthan (HCl) (encapsulated)solution which contained 15% (of total solution wt.) suspensionof“M2125 ™”¹ solid resin and encapsulated ammonium chloride 2 BSS Stage1: 0.3% PEI in 0.32% xanthan solution 8.2 None C Oil 320 Stage 2: Sameas #1 except no NH₄Cl was not used (HCl) 3 BSS Same as #2 exceptnon-encapsulated NH₄Cl 8.2 1 (non- C Oil 470 (HCl) encapsulated) 4 BSSSame as #1 except PTSA⁴ was used in Stage 1 to adjust pH, and 8.2 1 COil 490 50% “ASTRO MEL CR1 ™” used in Stage 2 (PTSA) (encapsulated) 5BSS Identical to #4 except non-encapsulated NH₄Cl was used 8.2 1 (non- COil 500 (PTSA) encapsulated) 6 BSS Identical to #1 except 50% resin andlarger particle size resin 8.2 None C Oil 585 “GM2125 ™”² was used withno NH₄Cl (HCl) 7 BSS Identical to #6 except 2% non-encapsulated ammonium8.2 2 (non- C Oil 650 chloride was used (HCl) encapsulated) 8 BereaIdentical to #7 (The core was treated with 4% KCl solution 8.2 2 (non- CWater 590 prior to Stage 1) (HCl) encapsulated) 9 Berea Identical to #6except that 0.2% “A1120 ™”³ by wt. of total resin. 8.2 None C Water 1430NH₄Cl was not used (HCl) 10 BSS Identical to #6 except J3167 ™ was usedas the resin. 8.2 None C Oil 600 NH₄Cl was not used (HCl) 11 BSSIdentical to #6 except larger particle size “GJ3167 ™” 8.2 None C Oil620 was used. NH₄Cl was not used (HCl) 12 BSS Identical to #9 except 70%“ASTRO MEL CR1 ™” was used. 8.2 None C Water 1070 NH₄Cl was not used(HCl) 13 BSS Formulation as in Procedure D with “GM2125 ™”² with 0.2%8.2 None D Water 530 “A1120 ™”³ by wt. of total resin (HCl)¹alpha-cellulose filled melamine-formaldehyde molding grade resin in thepowder form and was obtained from AC Molding in Dallas, Texas ²Same asin Note 1 except that the material is in the form of coarse grainsobtained from AC Molding in Dallas, Texas ³Available from OSiSpecialties Division of Witco Corporation, Greenwich, Connecticut underthe trade name “SILQUEST A1120 ™” ⁴para-toluenesulfonic acid

The results in Table 6 show that the treatment compositions containingsoluble resin and particulate resin along with appropriate catalystsystem(s) provide formation consolidation as well as concurrent chemicalcasing formation. Comparison of burst strengths in Experiment #1 inTable 5 and Experiments #1 and #3 in Table 6 show that additionalstrength due to chemical casing on the well bore wall is achieved byusing a soluble and insoluble resin combination. The results fromExperiments #8 and #9 suggest that a silane coupling agent can beadvantageously used to enhance the strengths of the chemical casing(compare with the results from Experiment #8 in Table 5). The resultsalso show that encapsulated catalyst systems can be used effectively tocure the particulate resin as well as soluble resin. For a drillingfluid to remain in the fluid state for the duration of drilling period,it is preferred that encapsulated catalysts instead of non-encapsulatedcatalysts be used.

Chemical Casing with No Formation Consolidation

In situations where only a casing is desired with no formationconsolidation, the process becomes a matter of depositing a filter cakeand curing it. The relevant tests were done by treating the cores withan aqueous mixture of solid resin, viscosifying resin, PEI and variouscatalysts without the dissolved resin. Two typical procedures areprovided below.

Procedure E (One-Stage Process): A 15% suspension of solid resin(“GM2125™” or “M2125™”) in a xanthan solution containing 3% PEI solutionwith pH adjusted as specified was used for the core treatment. Thetreatment when specified also contained a silane (“A1120™”) and/orcatalysts such as encapsulated or non-encapsulated ammonium chloride orpara-toluenesulfonic acid based catalysts when specified. The core wastreated until the flow essentially stopped. In all cases, a thin filtercake (1-4 mm thick) was formed. The curing was performed as describedearlier.

Procedure F (Two-Stage Process): In the first stage a 3% PEI solution indeionized water at proper pH was pumped through the core. This wasfollowed by treating the core with a 15% suspension of solid resin inxanthan solution (1.1 pounds per barrel) containing either encapsulatedor non-encapsulated ammonium chloride or para-toluenesulfonic acid ascatalysts. When specified, “A1120™”(N-beta-(aminoethyl)-gamma-aminopropyltrimethoxysilane) was also addedin amounts specified. In all cases, a thin filter cake of 1-3 mm thickwas formed. The curing process was carried out as described in theGeneral procedure.

TABLE 7 NH₄Cl, % pH Active Fluid For Burst Experiment Core (acid Amountby wt. Burst Strength, # Type Treatment Composition used) of Total ResinProcedure Strength psi 1 BSS Stage 1:3% PEI solution in water 8.2 None FOil 150 Stage 2:15% “M2125 ™” solid resin in 0.86% xanthan solution(HCl) 2 BSS Same as #1 with 1% NH₄Cl by wt. of resin in Stage 2 8.2 1(non- F Oil 190 (HCl) encapsulated) 3 BSS Aqueous suspension containing3% PEI, 0.32% xanthan; 15% 8.2 1 (non- E Oil 310 “M2125 ™” and ammoniumchloride (HCl) encapsulated) 4 BSS Same as #3 exceptpara-toluenesulfonic acid (PTSA) was 8.2 1 (non- E Oil 230 used toadjust pH, (PTSA) encapsulated)

The results in Table 7 show that a chemical casing formed by curing thefilter cake formed from particulate resin in combination withappropriate strength modifying polymers and catalyst system will havesufficient strength to extend the drilling operations by reducing casingpoints or eliminating some metal casing or liners altogether.

EXAMPLE 7

In this example, control of curing times with temperature, pH, resinconcentration and resin type are demonstrated. The curing times weremeasured by “TECHNE®” gelation timer manufactured by Techne (Cambridge)Limited, Duxford, Cambridge, UK.

For all the experiments, 100 grams of the resin mixture were used. Whenxanthan gum was used, initially a solution of 1.1 pounds barrel ofxanthan gum dissolved in water and then PEI solution was added to obtaina desired PEI concentration. This solution was mixed with the requiredamount of the melamine resin (“ASTRO MEL CR1™”) to obtain 10 grams ofthe mixture with the specified composition. The mixture was placed in aglass bottle and the gel time was measured. The results are shown inTable 8.

TABLE 8 Cure Cure Time, Time, Exper- Weight % % Resin Without With imentof PEI in in Total pH Temp., Xanthan Xanthan Comments on Thermoset WithComments on Thermoset # Total Mix Mix Final ° F. in mins. in mins. NoXanthan With Xanthan 1 3.5 30 8.55 140 110 — No free water, noshrinkage, hard solid 2 2.8 30 8.6 140 93 — No free water, no shrinkage,hard resin 3 2.5 50 8.56 140 78 — No free water, no shrinkage, hardsolid 4 2.4 20 8.15 140 48 43 No free water 5 2.4 20 9.17 160 143 — Nofree water; good solid 6 2.1 30 8.15 140 31 30 No free water 7 2.1 308.57 140 99 80 Uniform set; 2 ml free water Good solid; no free water 82.1 30 9.15 140 227 167 No free water; solid shrunk Uniform solid; nofree water 9 2.1 30 9.18 160 76 119 No free water; good solid No freewater; little shrinkage 10 2.1 30 8.5 160 28 130 No water; uniform solidGood solid; no free water 11 2.1 30 8.07 160 19 34 (pH 8.6) No freewater; uniform solid Solid; 5 ml free water 12 2.1 30 9.15 170 35 28 Nofree water; uniform solid Good solid; no shrinkage; 0.5 ml free water 132.1 30 8.6 170 20 59 Uniform solid; 0.7 ml free water No free water; noshrinkage; good solid 14 2.1 30 8.12 170 13 18 No free water, noshrinkage No shrinkage; no water; good 15 2.0 50 8.36 140 76 — 0.5 mlfree water, no shrinkage, hard solid 16 1.5 50 9.15 140 598 1000 7.5 mlfree water 5 ml free water 17 1.5 50 9.15 160 145 177 No free water;good solid 12 ml free water; solid shrunk; poor quality solid 18 1.5 507.6 160 21 33 (pH 8.0) 10 ml free water; hard, non-uniform solid No freewater; no shrinkage 19 1.5 50 9.03 170 79 76 Poor quality solid; 11.2 mlfree water Not uniform solid; air pockets in solid; no free water 20 1.430 8.15 140 36 33 No free water; brittle solid Air pockets in the sample21 1.4 30 9.15 140 211 246 Solid shrunk; 5 ml free water Non-uniformsolid w/air pockets; 7.5 ml free water 22 1.4 30 8.2 160 37 40 (pH 8.0)Uniform solid; 8.3 ml free water 15 ml free water; poor quality solid 231.4 30 9.06 170 31 34 Good solid; 2.4 ml free water Mushy solid; 14 mlfree water 24 1.4 30 7.95 170 8 29 No shrinkage; 0.6 ml free water Solidshrunk; 7 ml free water 25 1.0 50 8.15 140 65 120 26 1.0 50 9.15 140 965380 Solid not uniform; 15 ml free water Not good solid; 11 ml free water27 1.0 50 9.15 160 523 123 Significant solid shrinkage 16 ml free water;poor quality 28 1.0 50 8.2 160 90 2.3 (pH 7.7) Poor solid; 17 ml freewater 29 1.0 50 8.22 170 37 31 Poor solid, extensive shrinkage; 16 mlfree water; solid shrunk 18 ml free water 30 0.9 10 9.0 140 137 — Nofree water, spongy solid, no shrinkage 31 0.8 20 8.15 140 125 60 32 0.730 8.15 140 85 92 Solid not uniform Free water 33 0.5 50 8.15 140 142 8434 0.35 30 8.7 140 510

The results in Table 8 show that the curing times for the resincompositions can be controlled by pH, temperature, resin/PEI ratio andthe amounts of resin and PEI in the treatment composition. For example,the cure time can be decreased by increasing temperature, decreasing pHor resin/PEI ratio.

Thus, the present invention is well adapted to carry out the objects andattain the end and advantages mentioned as well as those which areinherent therein. While numerous changes may be made by those skilled inthe art, such changes are encompassed within the spirit of thisinvention as defined by the appended claims.

1. A method of forming a chemical casing while drilling through a zone or formation comprising drilling with a drilling fluid having a pH in the range of from about 6 to about 10 and that comprises water, a water soluble or water dispersible polymer which is capable of being cross-linked by a thermoset resin and causing the resin to be hard and tough when cured, a particulate curable solid thermoset resin and a water soluble or dispersible thermoset resin that cross-link the polymer, and a delayed dispersible acid-catalyst for curing the solid thermoset resin and the water soluble thermoset resin, whereby the drilling fluid forms a filter cake on the walls of the zone or formation that cures into a hard and tough cross-linked chemical casing thereon.
 2. The method of claim 1 wherein the water soluble or dispersible polymer which is cross-linked by the thermoset resins is selected from the group consisting of polymers containing one or more of hydroxyl, amide, carboxyl and epoxy functional groups.
 3. The method of claim 1 wherein the water soluble or dispersible polymer which is cross-linked by the thermoset resins is selected from the group consisting of polyvinylalcohol, polyvinylbutyral, polyesters, polyalkylacrylic acids, polyurethanes, acrylamide polymers, proteins, polyols and polysaccharides.
 4. The method of claim 3 wherein the polysaccharides are selected from the group consisting of chitosan, hydroxyethylcellulose, carboxymethylhydroxyethylcellulose, water soluble starches, guar gum, xanthan gum, welan gum, carragenan gum and arabic gum.
 5. The method of claim 1 wherein the particulate curable solid thermoset resin is selected from the group consisting of particulate solid melamine-formaldehyde type resins, particulate solid urea-formaldehyde type resins and particulate solid phenol-formaldehyde type resins.
 6. The method of claim 1 wherein the particulate curable solid thermoset resin is selected from the group consisting of an alkyl ether of a melamine-formaldehyde resin and an alkyl ether of a urea-formaldehyde resin.
 7. The method of claim 1 wherein the water soluble thermoset resin is selected from the group consisting of water soluble melamine-formaldehyde type resins, water soluble urea-formaldehyde type resins and water soluble phenol-formaldehyde type resins.
 8. The method of claim 1 wherein the water soluble or dispersible thermoset resin is selected from the group consisting of an alkyl ether of a melamine-formaldehyde resin and an alkyl ether of a urea-formaldehyde resin.
 9. The method of claim 1 wherein the acid in the delayed dispersible acid catalyst is an organic or inorganic acid selected from the group consisting of p-toluene sulfonic acid, dinonylnaphthalene sulfonic acid, dodecyl benzene sulfonic acid, oxalic acid, maleic acid, hexamic acid, a copolymer of phthalic and acrylic acid, trifluoromethane sulfonic acid, phosphonic acid, sulfuric acid, hydrochloric acid, sulfamic acid and ammonium salts that produce acids when dissolved in water.
 10. The method of claim 1 wherein the fluid further comprises one or more insoluble chemical casing reinforcing materials selected from the group consisting of carbon fibers, glass fibers, mineral fibers, cellulose fibers, silica, zeolite, alumina, calcium sulfate hemihydrate, acrylic latexes, polyol-polyesters and polyvinyl butyral.
 11. The method of claim 10 wherein the one or more insoluble chemical casing reinforcing materials are present in the fluid in an amount in the range of from about 2% to about 25% by weight of water in the fluid.
 12. The method of claim 1 wherein the water soluble or water dispersible polymer which is cross-linked by the thermoset resins is present in the fluid in an amount in the range of from about 0.5% to about 20% by weight of water in the drilling fluid.
 13. The method of claim 1 wherein the particulate curable solid thermoset resin is present in the fluid in an amount in the range of from about 5% to about 50% by weight of water in the drilling fluid.
 14. The method of claim 1 wherein the water soluble thermoset resin is present in the fluid in an amount in the range of from about 5% to about 80% by weight of water in the fluid.
 15. The method of claim 1 wherein the acid in the delayed dispersible acid catalyst is present in the fluid in an amount in the range of from about 0.5% to about 8% by weight of thermoset resin in the fluid.
 16. The method of claim 1 wherein the pH of the fluid is about
 8. 17. A method of forming a chemical casing in a well bore to improve the mechanical strength thereof or to provide zonal isolation, or both, while drilling the well bore comprising drilling the well bore with a drilling fluid having a pH in the range of from about 6 to about 10 and that comprises water, a water soluble or water dispersible polymer which is capable of being cross-linked by a thermoset resin and causing the resin to be hard and tough when cured, a particulate curable solid thermoset resin and a water soluble or dispersible thermoset resin that cross-link the polymer, and a delayed dispersible acid-catalyst for curing the solid thermoset resin and the water soluble thermoset resin, the drilling fluid forming a filter cake on the walls of the well bore that cures into a hard and tough cross-linked chemical casing thereon.
 18. The method of claim 17 wherein the water soluble or dispersible polymer which is cross-linked by the thermoset resins is selected from the group consisting of polymers containing one or more of hydroxyl, amide, carboxyl and epoxy functional groups.
 19. The method of claim 17 wherein the water soluble or dispersible polymer which is cross-linked by the thermoset resins is selected from the group consisting of polyvinylalcohol, polyvinylbutyral, polyesters, polyalkylacrylic acids, polyurethanes, acrylamide polymers, proteins, polyols and polysaccharides.
 20. The method of claim 19 wherein the polysaccharides are selected from the group consisting of chitosan, hydroxyethylcellulose, carboxymethylhydroxyethylcellulose, water soluble starches, guar gum, xanthan gum, welan gum, carragenan gum and arabic gum.
 21. The method of claim 17 wherein the particulate curable solid thermoset resin is selected from the group consisting of particulate solid melamine-formaldehyde type resins, particulate solid urea-formaldehyde type resins and particulate solid phenol-formaldehyde type resins.
 22. The method of claim 17 wherein the particulate curable solid thermoset resin is selected from the group consisting of an alkyl ether of a melamine-formaldehyde resin and an alkyl ether of a urea-formaldehyde resin.
 23. The method of claim 17 wherein the water soluble thermoset resin is selected from the group consisting of water soluble melamine-formaldehyde type resins, water soluble urea-formaldehyde type resins and water soluble phenol-formaldehyde type resins.
 24. The method of claim 17 wherein the water soluble or dispersible thermoset resin is selected from the group consisting of an alkyl ether of a melamine-formaldehyde resin and an alkyl ether of a urea-formaldehyde resin.
 25. The method of claim 17 wherein the acid in the delayed dispersible acid catalyst is an organic or inorganic acid selected from the group consisting of p-toluene sulfonic acid, dinonylnaphthalene sulfonic acid, dodecyl benzene sulfonic acid, oxalic acid, maleic acid, hexamic acid, a copolymer of phthalic and acrylic acid, trifluoromethane sulfonic acid, phosphonic acid, sulfuric acid, hydrochloric acid, sulfamic acid and ammonium salts that produce acids when dissolved in water.
 26. The method of claim 17 wherein the drilling fluid further comprises one or more insoluble chemical casing reinforcing materials selected from the group consisting of carbon fibers, glass fibers, mineral fibers, cellulose fibers, silica, zeolite, alumina, calcium sulfate hemihydrate, acrylic latexes, polyol-polyesters and polyvinyl butyral.
 27. The method of claim 26 wherein the one or more insoluble chemical casing reinforcing materials are present in the drilling fluid in an amount in the range of from about 2% to about 25% by weight of water in the drilling fluid.
 28. The method of claim 17 wherein the water soluble or water dispersible polymer which is cross-linked by the thermoset resins is present in the drilling fluid in an amount in the range of from about 0.5% to about 20% by weight of water in the drilling fluid.
 29. The method of claim 17 wherein the particulate curable solid thermoset resin is present in the drilling fluid in an amount in the range of from about 5% to about 50% by weight of water in the drilling fluid.
 30. The method of claim 17 wherein the water soluble thermoset resin is present in the drilling fluid in an amount in the range of from about 5% to about 80% by weight of water in the drilling fluid.
 31. The method of claim 17 wherein the acid in the delayed dispersible acid catalyst is present in the drilling fluid in an amount in the range of from about 0.5% to about 8% by weight of thermoset resin in the drilling fluid.
 32. The method of claim 17 wherein the pH of the drilling fluid is about
 8. 33. A method of forming a chemical casing in a well bore to improve the mechanical strength thereof or to provide zonal isolation, or both, while drilling the well bore comprising drilling the well bore with a drilling fluid having a pH of about 8 and that comprises water, a polysaccharide polymer which is capable of being cross-linked by a thermoset resin and causing the resin to be hard and tough when cured present in the drilling fluid in an amount in the range of from about 1% to about 10% by weight of water in the drilling fluid, a particulate curable solid alkyl ether of a melamine-formaldehyde resin present in the drilling fluid in an amount in the range of from about 10% to about 30% by weight of water in the drilling fluid and a water soluble or dispersible alkyl ether of melamine-formaldehyde resin present in the drilling fluid in an amount in the range of from about 20% to about 70% by weight of water in the drilling fluid that cross-link the polymer, and a dispersible delayed ammonium chloride acid catalyst for curing the particulate solid resin and the water soluble or dispersible resin present in the drilling fluid in an amount in the range of from about 1% to about 6% by weight of the resins in the drilling fluid, the drilling fluid forming a filter cake on the walls of the well bore that cures into a hard and tough cross-linked chemical casing thereon.
 34. A chemical casing made by a process of drilling through a zone or formation with a drilling fluid having a pH in the range of from about 6 to about 10 and that comprises water, a water soluble or water dispersible polymer which is capable of being cross-linked by a thermoset resin and causing the resin to be hard and tough when cured, a particulate curable solid thermoset resin and a water soluble or dispersible thermoset resin that cross-link the polymer, and a delayed dispersible acid-catalyst for curing the solid thermoset resin and the water soluble thermoset resin, wherein the drilling fluid forms a filter cake on the walls of the zone or formation that cures into a hard and tough cross-linked chemical casing thereon.
 35. The chemical casing of claim 34 wherein the water soluble or dispersible polymer which is cross-linked by the thermoset resins is selected from the group consisting of polymers containing one or more of hydroxyl, amide, carboxyl and epoxy functional groups.
 36. The chemical casing of claim 34 wherein the water soluble or dispersible polymer which is cross-linked by the thermoset resins is selected from the group consisting of polyvinylalcohol, polyvinylbutyral, polyesters, polyalkylacrylic acids, polyurethanes, acrylamide polymers, proteins, polyols and polysaccharides.
 37. The chemical casing of claim 34 wherein the polysaccharide is selected from the group consisting of chitosan, hydroxyethylcellulose, carboxymethylhydroxyethylcellulose, water soluble starches, guar gum, xanthan gum, welan gum, carragenan gum and arabic gum.
 38. The chemical casing of claim 34 wherein the particulate curable solid thermoset resin is selected from the group consisting of particulate solid melamine-formaldehyde type resins, particulate solid urea-formaldehyde type resins and particulate solid phenol-formaldehyde type resins.
 39. The chemical casing of claim 34 wherein the particulate curable solid thermoset resin is selected from the group consisting of an alkyl ether of a melamine-formaldehyde resin and an alkyl ether of a urea-formaldehyde resin.
 40. The chemical casing of claim 34 wherein the water soluble thermoset resin is selected from the group consisting of water soluble melamine-formaldehyde type resins, water soluble urea-formaldehyde type resins and water soluble phenol-formaldehyde type resins.
 41. The chemical casing of claim 34 wherein the water soluble or dispersible thermoset resin is selected from the group consisting of an alkyl ether of a melamine-formaldehyde resin and an alkyl ether of a urea-formaldehyde resin.
 42. The chemical casing of claim 34 wherein the acid in the delayed dispersible acid catalyst is an organic or inorganic acid selected from the group consisting of p-toluene sulfonic acid, dinonylnaphthalene sulfonic acid, dodecyl benzene sulfonic acid, oxalic acid, maleic acid, hexamic acid, a copolymer of phthalic and acrylic acid, trifluoromethane sulfonic acid, phosphonic acid, sulfuric acid, hydrochloric acid, sulfamic acid and ammonium salts that produce acids when dissolved in water.
 43. The chemical casing of claim 34 wherein the drilling fluid further comprises one or more insoluble chemical casing reinforcing materials selected from the group consisting of carbon fibers, glass fibers, mineral fibers, cellulose fibers, silica, zeolite, alumina, calcium sulfate hemihydrate, acrylic latexes, polyol-polyesters and polyvinyl butyral.
 44. The chemical casing of claim 43 wherein the one or more insoluble chemical casing reinforcing materials are present in the drilling fluid in an amount in the range of from about 2% to about 25% by weight of water in the drilling fluid.
 45. The chemical casing of claim 34 wherein the water soluble or water dispersible polymer which is cross-linked by the thermoset resins is present in the drilling fluid in an amount in the range of from about 0.5% to about 20% by weight of water in the drilling fluid.
 46. The chemical casing of claim 34 wherein the particulate curable solid thermoset resin is present in the drilling fluid in an amount in the range of from about 5% to about 50% by weight of water in the drilling fluid.
 47. The chemical casing of claim 34 wherein the water soluble thermoset resin is present in the drilling fluid in an amount in the range of from about 5% to about 80% by weight of water in the drilling fluid.
 48. The chemical casing of claim 34 wherein the acid in the delayed dispersible acid catalyst is present in the drilling fluid in an amount in the range of from about 0.5% to about 8% by weight of thermoset resin in the drilling fluid.
 49. The chemical casing of claim 34 wherein the pH of the drilling fluid is about
 8. 50. A chemical casing made by the process of drilling a well bore with a drilling fluid having a pH of about 8 and that comprises water, a polysaccharide polymer which is capable of being cross-linked by a thermoset resin and causing the resin to be hard and tough when cured present in the drilling fluid in an amount in the range of from about 1% to about 10% by weight of water in the drilling fluid, a particulate curable solid alkyl ether of a melamine-formaldehyde resin present in the drilling fluid in an amount in the range of from about 10% to about 30% by weight of water in the drilling fluid, a water soluble or dispersible alkyl ether of melamine-formaldehyde resin present in the drilling fluid in an amount in the range of from about 20% to about 70% by weight of water in the drilling fluid, and a dispersible delayed ammonium chloride acid catalyst for curing the particulate solid resin and the water soluble or dispersible resin present in the drilling fluid in an amount in the range of from about 1% to about 6% by weight of the resins in the drilling fluid, the drilling fluid forming a filter cake on the walls of the well bore that cures into a hard and tough cross-linked chemical casing thereon. 